Directional drilling involves controlling the direction of a wellbore as it is being drilled. Since wellbores are drilled in three dimensional space, the direction of a wellbore includes both its inclination relative to vertical as well as its azimuth. Usually the goal of directional drilling is to reach a target subterranean destination with the drill string.
It is often necessary to adjust the direction of the wellbore frequently while directional drilling, either to accommodate a planned change in direction or to compensate for unintended and unwanted deflection of the wellbore. Unwanted deflection may result from a variety of factors, including the characteristics of the formation being drilled, the makeup of the bottom hole drilling assembly and the manner in which the wellbore is being drilled. Directional drilling typically utilizes a combination of three basic techniques, each of which presents its own special features.
First, the entire drill string may be rotated from the surface, which in turn rotates a drilling bit connected to the end of the drill string. This technique, sometimes called "rotary drilling", is commonly used in non-directional drilling and in directional drilling where no change in direction is required or intended. This technique is relatively inexpensive because the use of specialized equipment such as downhole drilling motors can usually be kept to a minimum, but offers relatively little control over the direction of the wellbore.
Second, the drilling bit may be rotated by a downhole motor which is powered by the circulation of fluid supplied from the surface. This technique, sometimes called "sliding drilling", is typically used in directional drilling to effect a change in direction of a wellbore, such as in the building of an angle of deflection, and almost always involves the use of specialized equipment in addition to the downhole drilling motor, including bent subs or motor housings, steering tools and nonmagnetic drill string components. Furthermore, since the drill string is not rotated during sliding drilling, it is prone to sticking in the wellbore, particularly as the angle of deflection of the wellbore from the vertical increases. For this reason, and due also to the relatively high cost of sliding drilling, this technique is not typically used in directional drilling except where a change in direction is to be effected.
Third, rotation of the drill string may be superimposed upon rotation of the drilling bit by the downhole motor. Although this technique utilizes much of the specialized equipment used in the second technique, it may in some cases be cost effective because of the high drilling rates that can sometimes be achieved and also because a change from sliding drilling to the third technique and back again can be made without first tripping the drill string in and out of the wellbore.
The design of the bottom hole assembly of the drill string can enhance the effectiveness of all three of these techniques. In particular, in all three techniques the use of stabilizers in the bottom hole assembly can assist both in reducing unwanted deflection of a wellbore and in effecting a desired change in direction of the wellbore.
Conventional stabilizers can be divided into two broad categories. The first category includes rotating blade stabilizers which are incorporated into the drill string and either rotate or slide with the drill string. The second category includes non-rotating sleeve stabilizers which typically comprise a ribbed sleeve rotatably mounted on a mandrel so that during drilling operations, the sleeve does not rotate while the mandrel rotates or slides with the drill string. Rotating blade type stabilizers are far more common and versatile than non-rotating sleeve stabilizers, which tend to be used primarily in hard formations and where only mild wellbore deflections are experienced.
The primary purpose of using stabilizers in the bottom hole assembly is to stabilize the drilling bit that is attached to the distal end of the bottom hole assembly so that it rotates properly on its axis. When a bottom hole assembly is properly stabilized, the weight applied to the drilling bit can be optimized.
A secondary purpose of using stabilizers in the bottom hole assembly is to assist in steering the drill string so that the direction of the wellbore can be controlled. For example, properly positioned stabilizers can assist either in increasing or decreasing the deflection angle of the wellbore either by supporting the drill string near the drilling bit or by not supporting the drill string near the drilling bit.
Stabilizers are thus versatile tools which are useful in all three directional drilling techniques. The design of a bottom hole assembly requires consideration of where, what type and how many stabilizers should be incorporated into the drill string.
A single stabilizing point directly above the drill bit will tend to act as a pivot point for the drill string and may result in the drilling bit pushing to one side as weight on bit is increased, thus causing deflection of the wellbore. A second stabilizing point may reduce some of this effect, but preferably at least three stabilizing points are utilized if a straight wellbore is desired. The specific design of these stabilization points, which results in a "packed hole assembly", must be carefully determined in the context of the particular application.
In directional drilling applications, the pivot point provided by a near bit stabilizer can be used to advantage where deflection angle building is necessary. Alternatively, the deflection angle of the wellbore can sometimes be reduced by eliminating the near bit stabilizer but maintaining one or more stabilizers further up the drill string so that the drill string below the stabilizers will tend to drop down like a pendulum. This arrangement is sometimes referred to as a "packed pendulum assembly".
Since it is usually necessary to adjust the direction of the wellbore frequently during directional drilling, it can be seen that the desired number and location of stabilizers in the drill string may vary from time to time during drilling. Unfortunately, the entire drill string must first be removed from the wellbore in order to add or remove a conventional stabilizer to or from the drill string. This is extremely costly and time consuming.
Furthermore, conventional rotating blade type stabilizers are not generally suited for use near the drilling bit in situations where a downhole motor is used to rotate the drill string, since the stabilizer is then rotated by the motor along with the drilling bit, which can result in excessive torque loading on the motor. In addition, the stabilizer may be damaged by being rotated in the wellbore at the speeds produced by downhole motors.
Some attempts have been made in the prior art to address these problems. None of these attempts, however, have provided a fully satisfactory solution.
U.S. Pat. No. 4,407,377 (Russell) and U.S. Pat. No. 4,491,187 (Russell) both describe an adjustable gauge surface controlled rotating blade type stabilizer in which the stabilizer blades can be alternated between retracted and extended positions by alternately circulating and not circulating fluid through the stabilizer body. The radial position of the stabilizer blades is controlled by a grooved barrel cam and a complementary pin which control the axial movement of an expander sleeve associated with the stabilizer blades while the fluid is alternately circulated and not circulated. The adjustable gauge stabilizer taught by Russell offers flexibility in drilling procedures since the stabilizer blades can be extended or retracted downhole without first removing the drill string from the wellbore. It is intended, however, to be connected directly into the drill string and is therefore not well suited for use as a near bit stabilizer in conjunction with a downhole drilling motor. Where the adjustable gauge stabilizer described in Russell is used with a downhole drilling motor it must be connected into the drill string above the drilling motor, which will place it a considerable distance from the drilling bit.
U.S. Pat. No. 5,139,094 (Prevedel et al) and U.S. Pat. No. 5,181,576 (Askew et al) both describe a downhole drilling assembly including a downhole motor and a near bit rotating blade type stabilizer with stabilizer blades that can be alternated between retracted and extended positions. The assembly includes a mandrel, a sleeve mounted on the mandrel for limited rotation relative to the mandrel, and radially movable members on the sleeve which are extended or retracted by relative rotation between the mandrel and the sleeve. The mandrel is further mounted on a spindle which is coupled to a drive shaft extending from the power section of the downhole motor. As a result, the assembly described in the Prevedel and Askew patents provides for adjustable stabilization near the drilling bit in circumstances where a downhole motor is used. It is, however, subject to some significant limitations.
First, the extension and retraction of the stabilizer blades is effected through rotation of the drill string relative to the mandrel. This limits the control that can be exercised over the radial position of the stabilizer blades in the course of different stages of drilling, since rotation of the drill string in one direction will extend the stabilizer blades and rotation of the drill string in the other direction will retract the stabilizer blades. As acknowledged in the Prevedel and Askew patents, this can be detrimental due to the tendency of the drill string to oscillate about its longitudinal axis when sliding drilling is being conducted. In addition, rotation of the drill string is only effective to extend and retract the stabilizer blades if the sleeve is in frictional contact with the wellbore so that the mandrel can rotate relative to the sleeve as the drill string rotates. This requirement may render the stabilizer ineffective in situations where the wellbore is washed out.
Second, the stabilizer blades cannot be locked in either of the extended or retracted positions, which further limits the control that can be exercised over the radial position of the stabilizer blades. For example, the stabilizer described in Prevedel and Askew is designed to move to the extended position when drilling is taking place entirely or partially through rotation of the drill string, and is designed to move to the retracted position when sliding drilling is occurring. These positions may be entirely inconsistent with the wishes of the drilling crew, but without a locking mechanism associated with the stabilizer blades there is no way to perform drilling with the drill string rotating while the stabilizer blades are in the retracted position and there is no way to perform sliding drilling with the stabilizer blades in the extended position.
U.S. Pat. No. 5,265,684 (Rosenhauch) and U.S. Pat. No. 5,293,945 (Rosenhauch et al) describe a downhole adjustable rotating blade type stabilizer similar to that described in the Russell patents, in that the radial position of the stabilizer blades can be alternated between extended and retracted positions by circulating or not circulating fluid through the stabilizer body. Instead of a barrel cam and complementary pin, however, the adjustable stabilizer described in Rosenhauch uses a locking sleeve to fix the stabilizer blades in either the extended or retracted positions. This adjustable stabilizer appears to share the same disadvantages as the stabilizer described in Russell, in that it must be connected into the drill string above the downhole motor for directional drilling applications. A further disadvantage of the stabilizer described in Rosenhauch is that a two step procedure is necessary to extend and retract the stabilizer blades, since the stabilizer blades must be moved radially and the locking sleeve must be moved into or out of position.
Finally, Sperry-Sun Drilling Services, a division of Dresser Industries, Inc. manufactures an adjustable gauge rotating blade type stabilizer known as the Sperry-Sun AGS (TM) which is similar in principle to the adjustable stabilizer described in the Russell patents. In the Sperry-Sun AGS (TM), the radial position of the stabilizer blades is controlled by a grooved barrel cam and a complementary pin which control the axial movement of a series of ramps associated with the stabilizer blades while fluid is alternately circulated and not circulated through the stabilizer body. The Sperry-Sun AGS (TM) also includes a mechanism for signalling to the surface by using the pressure drop of the circulating fluid through the stabilizer body whether the stabilizer blades are in the extended or retracted position. For applications where a downhole drilling motor is used, the Sperry-Sun AGS (TM) must be connected into the drill string above the downhole motor, a significant distance from the drilling bit, and thus cannot be used in such applications as a near bit stabilizer.
There is therefore a need in the drilling industry for a stabilizer having one or more stabilizer elements which can be moved radially, which stabilizer can be connected into a drill string between the power unit of a downhole motor and the drilling bit.
By positioning one or more adjustable gauge stabilizers between the power unit and the drilling bit, perhaps in combination with non-adjustable stabilizers, more control can be maintained over the direction of the wellbore being drilled while still allowing for significant flexibility in the design of the bottom hole assembly. This flexibility can result in a single drilling assembly being capable of functioning as a multitude of bottom hole assembly designs, including a packed hole assembly, a packed pendulum assembly, and variations thereof. This flexibility may also result in a single bottom hole assembly being capable of establishing build rates and drop rates in addition to maintaining a constant angle of deviation during drilling.
There is also a general need in the drilling industry for drilling assemblies which incorporate components which contribute to the amount of control which can be maintained over the direction of the wellbore being drilled, which components are ideally located relatively near to the drilling bit.
U.S. Pat. No. 5,163,521 (Comeau et al), U.S. Pat. No. 5,410,303 (Comeau et al) and U.S. Pat. No. 5,602,541 (Comeau et al) describe a system for drilling deviated boreholes using a downhole motor in which wellbore inclination data is collected by a sensor or sensors positioned below the motor in close proximity to the drilling bit, which inclination data is transmitted via acoustic or electromagnetic signals to a receiver or receivers positioned above the motor for further transmission to the surface. This system is directed at overcoming problems associated with the reliability of inclination data which is collected a considerable distance from the drilling bit.
One disadvantage of the system described in Comeau is that the inclination sensors are positioned below the bent housing which is associated with the downhole motor, with the result that the accuracy of the system is dependent upon the toolface position and the bend magnitude of the bent housing.